R.08-08-009 ALJ/BWM/hkrDRAFT
ALJ/BWM/hkr/lilDRAFT Agenda ID #10148 (Rev. 2)
Ratesetting
4/14/2011 Item 42
Decision PROPOSED DECISION OF ALJ MATTSON (Mailed 2/11/2011)
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Continue Implementation and Administration of California Renewables Portfolio Standard Program. / Rulemaking 08-08-009(Filed August 21, 2008)
DECISION CONDITIONALLY ACCEPTING 2011
RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLANS
AND INTEGRATED RESOURCE PLAN SUPPLEMENTS
R.08-08-009 ALJ/BWM/hkr/lilDRAFT (Rev. 2)
TABLE OF CONTENTS
(Cont’d)
TitlePage
DECISION CONDITIONALLY ACCEPTING 2011 RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLANS AND INTEGRATED RESOURCE PLAN SUPPLEMENTS
1. Summary
2. Background
3. Overview of Plan Requirements and Commission Approach
3.1. Overview of Plan Requirements
3.2. Overview of Commission Approach
4. Issues Common to All Plans
4.1. Buyer-Directed Economic Curtailment
4.1.1. Pre-2011 Contract Interpretation
4.1.2. 2011 Pro Forma Contracts
4.1.3. Fully Deliverable
4.2. Integration Cost Adders
4.3. TRECs
4.4. Sunrise/Imperial Valley Remedial Measures
4.5. CAISO Standard Capacity Product
4.6. Pilot Program for Preapproval of Short-Term Contracts
4.7. Plan Organization and Standardization
4.8. Other Updates
4.9. MJU Supplemental Filing Date
4.10. Non-Disclosure Agreement
5. Limited Issues Specific to a Plan
5.1. PG&E
5.2. SCE
5.2.1. Modifications to Project Viability Calculator
5.2.2. Credit and Collateral Provisions
5.2.3. Shortlist Requirement (Interconnection Studies)
5.2.4. Other
5.3. SDG&E
5.3.1. TOD Factors
5.3.2. Other
5.4. PacifiCorp
5.5. Sierra (CalPeco)
6. Schedule for 2011 Solicitations and Organization of 2012 Plans
6.1. Schedule for 2011 Solicitation
6.2. Organization of 2012 Plans and IRPs
7. Additional Resources
8. Comments on Proposed Decision
9. Assignment of Proceeding
Findings of Fact
Conclusions of Law
ORDER
Appendix A: Summary of Key Items
Appendix B: Adopted Schedule for 2011 Solicitation
Appendix C: Links to Draft 2011 Procurement Plans
and Supplements to Integrated Resource Plans
for Renewables Portfolio Standard Program
Appendix D: Summary of Changes Proposed by IOUs in 2011 Plans
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R.08-08-009 ALJ/BWM/hkr/lilDRAFT (Rev. 2)
DECISION CONDITIONALLY ACCEPTING 2011
RENEWABLES PORTFOLIO STANDARD PROCUREMENT PLANS
AND INTEGRATED RESOURCE PLAN SUPPLEMENTS
1. Summary
The California Renewables Portfolio Standard (RPS) Program requires that each California electric utility procure, with limited exceptions, an annual minimum quantity of electricity generated from eligible facilities powered by renewable energy resources, with the quantity increasing at least 1% each year and reaching 20% by 2010. To fulfill this requirement, Southern California Edison Company (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E) must each prepare an RPS procurement plan (Plan), and update that Plan when directed by the Commission. The Commission is required to review and accept, modify or reject each Plan before commencement of renewables procurement. California Pacific Electric Company, LLC (CalPeco, previously Sierra Pacific Power Company) and PacifiCorp must each file a biennial Integrated Resource Plan (IRP), along with limited supplemental information. In years in which an IRP is not filed, CalPeco and PacifiCorp must each file more comprehensive Supplements. The Commission reviews each IRP and Supplement.
In this decision, we conditionally accept the recent Plans filed by SCE, PG&E, and SDG&E. We also review the Supplements to IRPs filed by CalPeco and PacifiCorp. Important steps we take include:
- Economic Curtailment: Direct that each utility include provisions for buyer-directed economic curtailment in its Final 2011 Plan.
- Tradable Renewable Energy Credits: Require that each utility include its intended use of tradable renewable energy credits in its Final 2011 Plan.
- Other Updates: Direct that each utility include use of recently adopted procurement tools in its Final 2011 Plan.
- Modify Non-Disclosure Agreements: Require that each utility modify its non-disclosure agreement or confidentiality provisions to permit discussion by not only utilities but also bidders/sellers of the bidding and negotiating process with the Commission and certain others.
- Schedule: Adopt a schedule for the 2011 solicitation, and a process for initiating the next solicitation.
SCE, PG&E, and SDG&E shall each, within 14 days of the date this order is mailed, file and serve a Final 2011 Plan, with a copy also filed on the Director of the Commission’s Energy Division. Each utility shall proceed to use its Final Plan for its RPS program and current solicitation, unless the Final Plan is suspended by the Executive Director or Energy Division Director within 21 days of the date this order is mailed. CalPeco and PacifiCorp shall each continue to use its IRP and Supplement. A more comprehensive summary of requirements for the Final Plans and future Supplements is in Appendix A. The solicitation schedule is in Appendix B.
We continue to employ the presumption that each utility may apply its own reasonable business judgment in running its solicitation, within the parameters we establish and the guidance we provide. Utilities ultimately remain responsible for program implementation, administration and success, within application of flexible compliance criteria. We will later judge the extent of that success, including the degree to which each utility implements Commission orders, elects to take Commission guidance, demonstrates creativity and vigor in program administration and execution, and reaches program targets, goals and requirements. This proceeding remains open.
2. Background
The first substantial procurement of non-utility generated electricity in California began in 1979 (Decision (D.) 91109, 3 CPUC2d 1), and resulted in the operation of approximately 11,000 megawatts (MW) of new cogeneration and small power production powerplants, with about 5,000MW using renewable fuels. Senate Bill (SB) 1078 established goals for seeking additional renewable procurement via the California Renewables Portfolio Standard (RPS) Program effective January 1, 2003.[1]
Several RPS procurement plans (Plans) have been reviewed by the Commission, and implemented under the RPS Program by Southern California Edison Company (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E) (collectively the investor-owned utilities or IOUs). On May 29, 2008, we completed the specification of obligations under the RPS Program for Sierra Pacific Power Company (Sierra, now California Pacific Electric Company, LLC or CalPeco)[2] and PacifiCorp (collectively the multi-jurisdictional utilities or MJUs). This includes the filing by an MJU of a biennial Integrated Resource Plan (IRP) in some years (along with limited supplemental information), and a more comprehensive Supplement to its IRP in other years. (D.08-05-029.)
By Amended Scoping Memo on November 2, 2009, the assigned Commissioner established the scope and schedule for Commission consideration of the next RPS Procurement Plans and IRP Supplements. The Amended Scoping Memo suggested a streamlined approach for presentation and consideration of those documents, consistent with the absence of legislation or Commission-identified issues requiring a comprehensive new Plan. The Amended Scoping Memo also encouraged the procuring utilities to simplify, harmonize, and seek uniformity in processes and documents. It also provided for the filing in some cases of a more comprehensive Plan.
On December 18, 2009, RPS Procurement Plans were filed by the IOUs.[3] Also on December 18, 2009, PacifiCorp filed a Supplement to its 2008 IRP, and Sierra filed a Supplement reporting no significant changes from its accepted 2009Supplement to its 2007 IRP. On January 19, 2010, comments were filed by the Commission’s Division of Ratepayer Advocates (DRA) and jointly by the California Wind Energy Association and Large-Scale Solar Association (CalWEA/LSA). On January 26, 2010, reply comments were filed by SCE, PG&E, SDG&E, Center for Energy Efficiency and Renewable Technologies (CEERT) and The Utility Reform Network (TURN).
Transmission Ranking Cost Reports (TRCRs) are also a required part of the Plan review process. On January 20, 2010, draft TRCRs were filed. Comments were due by February 10, 2010. No comments were filed.
On February 17, 2010, PG&E and SDG&E filed updated Plans.[4] On April9,2010, PG&E, SCE, and SDG&E filed amended Plans with updates related to tradable renewable energy credits (TRECs).[5] On April 23, 2010, TURN, DRA, CalWEA/LSA, and Solar Alliance (SA) filed comments. On May 3, 2010, DRA, SDG&E, SCE, PG&E, and CalWEA/LSA filed reply comments.
On June 6, 2010, PG&E filed an amended Plan with updates related to its solar photovoltaic (PV) program.[6] On June 18, 2010, DRA, CalWEA/LSA and L.Jan Reid (Reid) filed comments. On June 25, 2010, PG&E filed reply comments.
On June 12, 2010, SCE amended its Plan to address economic curtailment. This amendment followed an all-party meeting regarding curtailment provisions in RPS Plans held by the assigned Commissioner on May 6, 2010. On July2,2010, CalWEA/LSA and Independent Energy Producers Association (IEP) filed responses to SCE’s amended Plan. On July 12, 2010, SCE filed a reply.
On August 24, 2010, IEP and CalWEA filed late comments regarding oneitem in SCE’s Plan.[7] On September 8, 2010, SCE filed timely reply comments, and on September 22, 2010, CEERT filed late reply comments.[8]
Motions for hearing were due January 28, 2010, or later as appropriate. No motions for hearing were filed. No hearing was held.
3. Overview of Plan Requirements and Commission Approach
3.1. Overview of Plan Requirements
Each utility covered by the RPS Program is required each calendar year to procure, with some exceptions, a minimum quantity of electricity generated from eligible facilities powered by renewable energy resources.[9] This minimum is measured as a percentage of total retail sales and is generally known as the annual procurement target, or APT. Each utility is also required, with some exceptions, to increase its total procurement from eligible renewable energy resources by at least 1% of retail sales per year until it reaches 20%. This is generally known as the incremental procurement target, or IPT, and results in annual incremental growth in the APT. (§ 399.15.) Each utility must, subject to certain flexible compliance provisions, reach 20% by 2010.[10] Procuring utilities have a three-year flexible compliance window to meet each year’s target, thereby potentially allowing a utility until 2013 to meet 2010 targets. Failure to reach an annual target exposes the utility to possible penalty.
Each utility, as part of fulfilling these requirements, must prepare a Plan for the procurement of RPS-eligible energy. The Plan must include but is not limited to (a) an assessment of demand and supply to determine the optimal mix of renewable resources, (b) use of flexible compliance mechanisms established by the Commission, and (c) a bid solicitation. (§ 399.14(a)(3).)
IOU Plans are subject to Commission review and acceptance, modification or rejection prior to the commencement of renewable resource procurement. (§399.14; D.03-06-071.[11]) An IOU must update its Plan when required by the Commission. (§ 399.14.) For MJUs, we review the biennial IRP (with limited supplemental information) and, in years without an IRP, an expanded Supplement to the IRP.[12] (D.08-05-029.) The Commission does not require the MJUs to engage in the same solicitation cycle required of the IOUs. Therefore, the MJUs need not await Commission action before their commencement of renewable resource procurement.
Appendix C contains links to IOU draft Plans and MJU Supplements which we review in this decision.
3.2. Overview of Commission Approach
We have followed an approach of “flexibility with accountability” as we allow utilities to fulfill their duties under the Program. That is, we have granted RPS-obligated utilities considerable flexibility in the way they satisfy RPS Program goals. In exchange, each utility must meet its RPS Program targets, within application of flexible compliance criteria, subject to penalties for unexcused failures to meet targets.
Our responsibility includes accepting, rejecting or modifying IOU Plans (or updates to those Plans) before solicitations may begin. We also review the MJU IRPs and IRP Supplements. We do not, however, write any Plan, IRP or Supplement, or dictate with precise detail the specific language of any Plan, IRP or Supplement. Nor do we micromanage what is in the Plan, IRP or Supplement. Rather, each utility has considerable flexibility to develop and propose its own Plan, IRP, and Supplement. Our review is at a reasonably high level. Similarly, we do not take over the procurement process. Each utility is ultimately responsible for achieving successful procurement using its Plan, IRP or Supplement pursuant to, and consistent with, the RPS Program.
Our responsibility also includes reviewing the results of solicitations. It includes accepting or rejecting proposed contracts, based on consistency with approved Plans, when the contracts are submitted for approval. (§ 399.14(d).) The Plans accepted herein are a fundamental, but not necessarily the only, part of that review.[13] Similarly, the Supplements will be a fundamental, but not necessarily the only, consideration when reviewing an MJU’s compliance with RPS Program obligations.
We have conditionally accepted prior Plans, provided guidance, taken steps to broaden and enhance the quantity and quality of RPS bids, and improved the contracting process.[14] We continue to do so here. We do not repeat existing Commission directions, requirements, and guidance. Rather, all existing directions and guidance remain unchanged unless specifically addressed otherwise herein.
In this order, we discuss limited issues which require our attention before the next solicitation. We first address several issues common to most if not all Plans. We then examine issues specific to a particular Plan or Supplement. We conclude by adopting the schedule for 2011 Plan solicitations, and the process for considering 2012 Plans.
4. Issues Common to All Plans
We address the following issues common to most, if not all Plans:
- Buyer-Directed Economic Curtailment
- Integration Cost Adders
- Tradable Renewable Energy Credits (TRECs)
- Sunrise/Imperial Valley Remedial Measures
- California Independent System Operator (CAISO) Standard Capacity Product (SCP)
- Pilot Programs for Preapproval of Short-Term Contracts
- Plan Organization and Standardization
- Other Updates
- MJU Supplemental Filing Date
- Non-Disclosure Agreements
4.1. Buyer-Directed Economic Curtailment
The CAISO recently implemented its Market Redesign and Technology Upgrade (MRTU). MRTU uses markets and market-determined prices to schedule and dispatch generation resources. In particular, it uses Locational Marginal Prices (LMPs) as price signals reflecting electricity supply and demand in multiple locations. Over time, LMPs could also give price signals that influence project location.
To address MRTU issues, SCE and PG&E propose modifying pro forma (model) contract terms and solicitation protocols. SCE and PG&E propose terms that would allow the utility, as buyer and scheduling coordinator, to decline procurement from a renewable generator if the day-ahead price makes the delivery uneconomic. We refer to this as buyer-directed economic curtailment, or economic curtailment.[15] We address three economic curtailment issues presented by parties:
1. Pre-2011 contract interpretation;
2. 2011 pro forma contracts; and
3. Requirement that project be fully deliverable.
4.1.1. Pre-2011 Contract Interpretation
In its draft 2011 Plan, SCE asserts that its prior pro forma contracts allow SCE to direct curtailment of an RPS project at the request of either the CAISO or SCE.[16] SCE also says it has the right to withhold payment to the seller for energy that the facility could have delivered but for the curtailment ordered by SCE.
CalWEA/LSA disagree, asserting that prior pro forma contracts do not allow unlimited curtailment by SCE for economic or other reasons. They claim that SCE’s interpretation jeopardizes the ability of developers to find project financing.[17] TURN, IEP, and CEERT agree. In addition, TURN and IEP say that SCE’s interpretation could result in significant contract price increases to cover the risk of substantial curtailment.[18] CEERT states that SCE’s interpretation is inconsistent with prior power purchase agreements (PPAs), prior Plans, and Commission decisions.[19]
We decline to interpret terms of executed contracts. Rather, disputes over terms in executed contracts are subject to the dispute resolution provisions of the contract. Parties should use those provisions.
Some pre-2011 pro forma contracts may not yet be executed, but might be the subject of ongoing negotiations. If so, buyer and seller may negotiate a mutually acceptable solution regarding this issue in light of SCE’s statements. We need not disturb the negotiation process.
We note, however, that our approval of prior Plans and pro forma contracts has been, and is, in the context of “flexibility with accountability.” (D.09-06-018 at 9.) Each utility is “ultimately responsible for proposing and executing reasonable Plans that achieve RPS targets.” (Id. at 53.) This responsibility includes contract execution and ongoing contract administration. SCE’s interpretation and enforcement of prior pro forma and executed contracts is a factor in that administration. If SCE fails to execute contracts or a contract fails due to unreasonable administration by SCE, with SCE thereby failing to reach its program targets (e.g., 20% by 2010), SCE is subject to being held accountable. This includes the potential of SCE paying penalties for failing to reach targets.[20]
4.1.2. 2011 Pro Forma Contracts
PG&E and SCE propose 2011 pro forma contracts allowing economic curtailment. SDG&E makes no such proposal. For the reasons explained below, we direct that all three IOUs include economic curtailment provisions in their Final 2011 Plans, and reveal limited specific congestion cost information to the extent used in LCBF evaluations. We first briefly describe the proposals.
PG&E proposes economic curtailment up to five percent of the project’s expected annual generation per year, with PG&E paying the seller the full contract price for curtailed energy. The reduced generation, however, may result in the seller losing certain tax advantages (i.e., production tax credits or PTC). PG&E does not propose reimbursement for the lost PTCs.
SCE first proposed unbounded economic curtailment. SCE modified its proposal based on parties’ comments. As modified, SCE proposes economic curtailment without compensation (and without reimbursement for lost PTCs) up to a pre-determined, negotiated number of hours capped at between 50 and 200 per year. Economic curtailment in excess of the cap is to be compensated by SCE at the contract price plus the value of any lost PTCs. At the end of the contract SCE would have the option to buy generation equal to twice the total amount that was curtailed over the life of the contract in excess of the cap at 50percent of the contract price. This option could be exercised for up to twoyears past the conclusion of the original contract term.